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Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The average reservoir pressure plays an important role in all phases of reservoir appraisal. Although buildup pressure tests are meant to be used for the estimation of this parameter, drawdown tests can also be used by a mathematical combination with material balance. Therefore, in this study, the TDS Technique is applied to drawdown tests for the development of expressions to obtain the average reservoir pressure for vertical wells in homogeneous and heterogeneous systems, and fractured wells in homogeneous formations, as well. Applications to three simulated and one field cases were successfully compared to those from material balance providing absolute derivation errors lower than 3%. [ABSTRACT FROM AUTHOR]

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The equivalent circulation density (ECD) is a very important parameter in drilling high-pressure high-temperature and deepwater wells. ECD is a key parameter during drilling through formations where the margin between the pore pressure and the fracture pressure (FP) is narrow. In these critical formations, the ECD is used to control the formation pressure and prevent kicks. Recent approaches in oilfields to determine ECD depend mainly on using expensive downhole sensors for providing real-time values of ECD. Most of these tools have operational limitations such as high pressure and high temperature which may prevent using these tools in downhole conditions. The objective of this paper is to develop a new approach for predicting ECD using artificial intelligence (AI) techniques from surface drilling parameters [mud weight, drill pipe pressure, and rate of penetration (ROP)]. 2376 data points were used to develop the AI models. The data were collected during the drilling of an 8.5″ vertical hole section. Two AI models were used to estimate the ECD: artificial neural network (ANN) and adaptive neuro-fuzzy inference system (ANFIS). An empirical correlation for ECD was derived from the optimized ANN model by extracting the weights and biases. The developed ANN and ANFIS models were able to calculate ECD with a correlation coefficient (R) of 0.99 and average absolute percentage error of 0.22% for ANN and ANFIS models, respectively. The developed empirical correlation for the ANN model can be used during well design to choose a correct mud weight to safely drill the well based on the expected drilling parameters. It will also minimize the drilling problems related to ECD such as losses or gains especially in critical situations where the margin between the pore and fracture pressure is very narrow. In addition, using this technique will save cost and time by reducing the need for expensive, complicated downhole tools. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The purpose of the paper was to study hydrodynamic peculiarities of the aquifers of Volyn-Podillya oil and gas-bearing region and their impact on the formation and conservation of gas deposits. The research area is located in the western Ukraine and covers the structures of the Eastern European and the Western European platforms. At present, Lokachi and Velyki Mosty gas fields are discovered here in the deposits of the Middle and Upper Devonian. Non-commercial volumes of gas and oil were received in some exploration wells. Research methodology was based on the evaluation of water initial formation pressures and static levels that were obtained from the funds of the State Enterprise "Lvivgazvydobuvannia" and State Enterprise "Zakhidukrgeologia”. The formation pressures were transformed to one plane of comparison. Also the hydrodynamic characteristics were studied in this work on the basis of the hydrostatic coefficient (P f/P e) in order to evaluate the impact of the factors that determine the nature and form the state of the hydrodynamic field. The maps of the formation pressures and hydrostatic coefficients were constructed and interpreted. Results of researches. It was found out that the parameters of hydrodynamic fields of the Upper Proterozoic, Cambrian, and Lower-Devonian aquifers complexes of the Volyn-Podillya ORG have the features of an exfiltration system. The hydrodynamic tension extends from the most abyssal parts of the sedimentary basin to its peripheral parts. Formation pressures are caused by an increase in the volume of waters due to their squeezing out of clay sediments that have the ability to significant compression into weakly compression sandy rocks. The hydrodynamic energy of the Middle-Upper Devonian aquifer complex is directed from the periphery to its central (the most submerged) part. The peripheral parts have the characteristics of the infiltration waterpressure system. It was established that the hydrodynamic field of the Volyn-Podillya ORG compared with the Bilche- Volytsya ORG is marked by a much lower power due to weak effect of exfiltration in the aquifers and the absence of sustained lithological and tectonic screens. The lateral hydrodynamic field, investigated on the basis of the hydrostatic coefficient, increases from the south to the north. A certain spatial relationship of the isolines of hydrostatic coefficient with diagonal disjunctive breaks is observed. This can determine them as a way of the water-hydrocarbon mixtures migration. Gas deposits of Lokachy and Velyki Mosty fields are located in areas with higher values of the hydrostatic coefficient. Distribution of the hydrostatic coefficient in the section of Lokachi gas field indicates the connection of its overhydrostatic values with the existing gas deposits. Hydrodynamic isolation of the structures promoted conservation of hydrocarbon deposits from mechanical and biochemical destruction. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

During drilling activities, geological parameters of a well to be drilled (target well) can be predicted within a limited interval based on multi-well data fusion which aims at ensuring a drilling safety, enhancement of drilling efficiency, reduction of drilling cost as well as acquiring accurate measurements in respect to Oil and Gas protection layers. This work presents a method of uncertainty analysis prediction of pressures using fusion data (formation pressures) from adjacent multi-well. The Eaton method, effective stress theory, and mathematical confidence interval were the various methods used to establish the formation pressure matrix of the target well. The results revealed that due to the complexity and variability of the formations, data interpretation errors of the geological parameters were inevitable. Therefore, the probability density distribution function was established through stratigraphy, probability statistics, and information diffusion. Moreover, the real value of the wells’ formation pressure (target well) was within the distribution interval of multi-well data fusion. Hence, the developed method cannot only effectively reduce the interval of geological parameter of the target well but also enhance the accuracy of parameters prediction. [ABSTRACT FROM AUTHOR]

The low porosity and permeability of shale deposits is due to the complex structure of the pores. Due to the threshold pressure gradient, fluid seepage in low-permeable reservoirs does not obey Darcy's law. Horizontal well drilling and fracturing treatment are effective methods of developing lowpermeable reservoirs, since these methods increase the well drainage area. In the present study a mathematical model of gas flow in different types of wells is obtained on the basis of seepage theory. The pressure distribution and relationship between the threshold pressure gradient and limit well spacing are obtained using the point-source function and Laplace transforms. The limit well spacing increases with decreasing threshold pressure gradient. The method is of importance for determining an appropriate spacing between different combinations of different types of wells in the development of shale gas. [ABSTRACT FROM AUTHOR]

Water flooding disasters are one of the five natural coal-mining disasters that threaten the lives of coal miners. The main causes of this flooding are water-conducting fractured zones within coal seams. However, when resistivity methods are used to detect water-conducting fractured zones in coal seams, incorrect conclusions can be drawn because of electrical anisotropy within the water-conducting fractured zones. We present, in this paper, a new geo-electrical model based on the geology of water-conducting fractured zones in coal seams. Factors that influence electrical anisotropy were analyzed, including formation water resistivity, porosity, fracture density, and fracture surface roughness, pressure, and dip angle. Numerical simulation was used to evaluate the proposed electrical method. The results demonstrate a closed relationship between the shape of apparent resistivity and the strike and dip of a fracture. Hence, the findings of this paper provide a practical resistivity method for coal-mining production. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Given the complexity involved when modeling heterogeneous and anisotropic formations, this condition is usually ignored, supposing that the well is surrounded by a homogenous and isotropic medium. The main objective of this paper is to present a method that shows the error that might occur when the condition of homogeneity and isotropy is not satisfied, when determining collapse pressure in a formation containing planes of weakness. Although the literature presents some studies, there is not a clear method for determining the collapse pressure of a well that takes into account the mechanical properties of the planes of weakness contained in the formation. The proposed method is based on the Mohr Coulomb criterion for homogeneous and isotropic formations and the criterion of Jaeger and Cook (1979) for laminated anisotropic media. It constitutes a robust tool that calculates the collapse pressure in highly complex configurations, contributing thus to prevent waste of time and money by more accurately considering the actual behavior of laminated formations. The method includes: the deduction of the direction cosine equation, the proposal of an objective function, the construction of a collapse pressure profile, and the sensitivity analysis of the collapse pressure with colored rosettes. A real case was selected to implement the proposed method.Dada la complejidad presentada cuando se modelan formaciones heterogéneas y anisotrópicas por lo general se opta por omitir tal condición, asumiendo que el pozo en las zonas de interés está rodeado de un medio homogéneo e isotrópico. El objetivo principal de este artículo es presentar una metodología que muestra el error que se puede llegar a cometer cuando la condición de homogeneidad e isotropía no se cumple a la hora de determinar la presión de colapso, en una formación que contiene planos de debilidad. Aunque la literatura presenta algunos estudios, no propone una metodología clara para determinar la presión de colapso en un pozo, teniendo en cuenta las propiedades mecánicas de los planos de debilidad contenidos en la formación. La metodología propuesta está basada en el criterio de Mohr Coulomb para formaciones homogéneas e isotrópicas, y en el criterio de Jaeger y Cook (1979) para medios anisotrópicos laminados, y constituye una herramienta robusta que permite calcular las presiones de colapso en formaciones altamente complejas, contribuyendo así a evitar pérdidas de tiempo y dinero al considerar de manera más precisa el comportamiento real de formaciones laminadas. La metodología incluye: la deducción de las ecuaciones de los cosenos directores, el planteamiento de una función objetivo, la construcción de un perfil de presiones de colapso y el análisis de sensibilidad de la presión de colapso mediante rosetas de colores. Para la aplicación de la metodología propuesta, se seleccionó un caso real.

Sichuan Basin is a typical superimposed basin, which experienced multi-phase tectonic movements, meanwhile Sinian-Cambrian underwent complex hydrocarbon accumulation processes, causing exploration difficulties in the past 60 years. Based on the microscopic evidence of fluid inclusions, combined with basin-modelling, this paper determines stages and time of hydrocarbon accumulation, reconstructs evolution of formation pressure and dynamic processes of hydrocarbon accumulation in Sinian Dengying Formation-Cambrian Longwangmiao Formation of Gaoshiti-Moxi structure. Three stages of inclusions are detected, including a stage of yellow-yellowgreen fluorescent oil inclusions, a stage of blue fluorescent oil-gas inclusions and a stage of non-fluorescent gas inclusions, reflecting the study area has experienced a series of complex hydrocarbon accumulation processes, such as formation of paleo-oil reservoirs, cracking of crude oil, formation of paleo-gas reservoirs and adjustment to present gas reservoirs, which occurred during 219-188, 192-146 and 168-0 Ma respectively. During the period of crude oil cracking, Dengying Formation-Longwangmiao Formation showed weak overpressure to overpressure characteristics, then after adjustment of paleo-gas reservoirs to present gas reservoirs, the pressure in Dengying Formation changed into overpressure but finally reduced to normal pressure system. However, due to excellent preservation conditions, the overpressure strength in Longwangmiao Formation only slightly decreased and was still kept to this day. [ABSTRACT FROM AUTHOR]

Copyright of China Sciencepaper is the property of China Sciencepaper and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The formation pressure plays a very important role in drilling engineering. So it is of great significance to predict formation pressure before drilling. In order to solve the problem, the concept of formation matrix and wellbore matrix were put forward. Also the method of epitaxial transplantation for the regional formation pressure was proposed. With the concept of wellbore pressure matrix, the target wellbore pressure matrix can be built by dealing with the adjacent wellbore pressure using the method of depth adjustment and weighted distance correction. Finally, we can obtain the formation pressure of the target well. Case study of Qinghai Oilfield was carried out to test the method. Through comparative analysis, the maximum relative error of the transplantation pressure and logging interpretation pressure is 4.2%. The result indicated that the accuracy and reliability of the method can meet the engineering requirement. This is conductive to designers to predict formation pressure which can provide the basis for the casing design and the selection of the drilling fluid density. [ABSTRACT FROM AUTHOR]

The most important stages of formation testing while drilling (FTWD) are mainly the pressure drawdown and build-up. Therefore, the main objectives of this research are to propose analytical solutions of the pressure response, verify the validity of the analytical model, and analyze the characteristics of the pressure response of FTWD tools via theoretical and experimental tests. The mathematical model of the pressure response is proposed, and the analytical solutions are obtained by application of successive integral transforms; the influences of heterogeneity, skin effect, storage effect, and supercharging effect are used to modify the analytical solution. The experimental apparatus was designed to verify the validity of the analytical model; the laboratory experiments of four types of representative samples were conducted. Finally, the characteristics of pressure response with varying formation permeability, heterogeneity, skin effect, storage effect, drawdown flow-rate, supercharging effect, etc. are discussed. The results indicate that the simulated pressure response curves are in good agreement with the laboratory experimental results, although the error is higher in the initial stage of pressure build-up (the maximum error is less than 20% for the ultra-low permeability formation), but the error of the calculated pore pressure, less than 10%, belongs to an acceptable range of error, i.e., the analytic model could be applicable in a wide permeability with the range from 1 mD to 100 mD. The pressure drawdown declines rapidly in the stage of withdrawing formation fluids and then recovers slowly to the original pore pressure during FTWD testing. The formation permeability and drawdown flow-rate have strong impacts, and the supercharging effect, skin effect, and heterogeneity have significant impacts; however, the storage effect has a relatively smaller impact on the pressure response of the FTWD tools. This analytical model is different from, but more practical than, the conventional method. [ABSTRACT FROM AUTHOR]

Pressures are critical for safe drilling of high temperature geothermal reservoir. In this paper, fracturing pressure, formation pressure, leaking pressure and annular friction loss and equivalent circulating density of the first medium-deep geothermal well ZK212 is calculated and analyzed by conducting leakoff test and observing the wellbore water table, and contour map of zero pressure point is drawn by the integration of investigation data in 1990s, which could be used to aid designing drilling fluid system avoiding blowout and fracturing formation. [ABSTRACT FROM AUTHOR]

Downhole formation pressure data can be difficult to obtain and the quality of the data produced varies significantly with age, tool type and geology. Furthermore, even if a new well is characterised effectively and high quality data obtained, the radius of investigation is small compared to the size of the area typically being assessed. Nevertheless, understanding the subsurface formation pressure system is a prerequisite for any basin or reservoir evaluation during exploration, appraisal and production. It requires integrating pressure and subsurface data from spatially disparate wells, and requires direct, quantitative comparison of historical and contemporary data-sets. This comparison needs to be objective, repeatable and robust. This paper describes a qualitative system for systematically and objectively comparing all types of formation pressure measurements to provide a basis for a qualitative interpretation of the subsurface formation pressure system. The application of the system consists of a set of questions designed to assess the quality and quantity of formation pressure data available from information in the well completion report. Each question defines quantitative limits for key pressure test parameters that determine the quality class of the formation pressure of that test. The questions require a 'yes' or 'no' answer, and the cumulative set of answers results in a code that reflects the overall quality of the data. The resulting set of codes can be used directly or can be further subdivided into a set of five reliability classes. The system does not assess the accuracy of an individual pressure test, but provides a context for meaningful comparisons to be made of formation pressure data acquired under spatially and temporally disparate conditions. This allows for an interpretation of the data to be made that accounts for the variable reliability of individual data points. The system is generic and can be applied to any basin, onshore or offshore. It is suitable for field-scale studies up to basin-scale studies and can be applied to producing or non-producing data. This paper outlines the underlying principles and the methodology required to apply the quality code system. It includes examples of how application of both the quality codes and the reliability classes can simplify the interpretation of a scattered data-set and provide tools to effectively communicate the results. [ABSTRACT FROM AUTHOR]

Due to the sedimentary environment, diagenesis effect, and tectogenesis effect, the geometry form of sandstone shows heterogeneity, which affects the water flooding efficiency, especially in continental sedimentary reservoir. First, according to distribution characters of sandstone, an idealized mode can be obtained. The 2-D and two-phase mathematical mode at certain inlet and outlet pressure was established. By applying discrete and differential numerical methods, the cumulative oil production under two conditions can be calculated. It is higher when the inlet end is wider part of the sandstone. Second, using streamline numerical simulation to build similar injection and production horizontal well model, the authors obtained analog and study sweep efficiency of different displacement directions. Last, by adopting reservoir numerical simulation method, the influence of geometric form of sandstone on water flooding efficiency of well pattern was further studied. The conclusion was drawn that when injector was deployed in narrow part of sandstone and oil well in the wide part, the speed of water flood front was fast, and water breakthrough times were shorter, which led to rapid water cut rises. Under certain bottomhole flowing pressure, formation pressure surrounding injector was a little higher, water injection rate dropped, and cumulative oil production decreased. [ABSTRACT FROM PUBLISHER]

The paper presents the theoretical an experimental analysis of the regularities in the change of the permeability of fractures under the normal stress effect in the oil and gas reservoirs. The applicability of the permeability variation law based on the fracture model by Barton and Bandis has been exemplified in terms of the Yurubcheno-Tokhoma oil and gas condensate field. [ABSTRACT FROM AUTHOR]

Abstract: The tight sandstone gas accumulation is mainly driven by overpressure arising from the gas generation in source rocks. This paper proposes a quantitative computation model for the pressurization from gas generation in source rocks, establishes a dynamic equilibrium equation and a modeling process for tight sandstone gas accumulation, and simulates the gas generation quantity and source rock overpressure history in the Hechuan-Tongnan area of the Sichuan Basin. The modeling reveals that: (1) The gas generation intensity determines the degree of pressurization from gas generation, whereas the reservoir property determines the distribution of gas reservoirs; the conventional gas reservoir is complementary with the tight sandstone gas reservoir in terms of horizontal and vertical distribution, the former is mainly distributed at the top of reservoir with porosity over 7% on local structural highs while the latter is mainly distributed at the bottom of reservoir on local structural lows near source rocks of large gas generation quantity. (2) During the uplifting process from the maximum burial depth (65 Ma) to the current burial depth, because of the pressure drop of formation water and the increase of gas-water pressure difference, the tight sandstone gas migrates farther and increases in accumulation quantity; however, the conventional gas does not migrate basically and has no increase in accumulation quantity; (3) The quantity of the tight sandstone gas in the T3x2 is 5.9 times that of the conventional gas, and the undiscovered resource is mainly tight sandstone gas distributed in northeast of Hechuan, and north and southeast of Tongnan. [Copyright &y& Elsevier]